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By Fred C., Bond

DETERMINATIONS of circulating load in a classifier operating in closed circuit with a grinding mill are usually made from screen analyses of the mill feed and classifier products. The percentage remaining on someone selected screen size must be used in the calculation, and, because of the wide variation in average particle size between the mill feed and classifier overflow, an accurate and representative result at the selected mesh is often difficult to obtain. To overcome this difficulty and reduce the time required in making the determination, I have devised a method which uses the liquid-solid relationship in the circuit rather than screen analyses. The quantities required for the calculation include only the usual dilution and feed tonnage measurements, which should be made regularly in the course of ordinary mill operation and, in addition, the amount of new water added to the classifier, or to the head of the mill with the new feed. If measurements are obtained on both of these quantities it is possible to check the calculated circulating load, and to calculate the percentage of moisture in the new feed to the mill; or, if the latter is known, to check the feed tonnage.

Jan 1, 1937

By A. L. Jr. Pozzi, A. O. Garder, D. W. Peaceman

A new numerical method is proposed for the solution of multidimensional miscible displacement problems. Besides the usual stationary grid associated with numerical procedures, the method uses moving points for which positions and concentrations are computed each time step. Based on the method of characteristics for treating combined transport and dispersion, the method applies equally well to any number of dimensions and, in contrast with other numerical procedures, properly takes into account the physical dispersion, no matter how small. Extensive tests show that accurate solutions of one-dimensional problems can be obtained over a wide range of values of the dispersion coefficient, including zero. They also show that the moving points do not need to be uniformly spaced, and that increasing the number of moving points beyond 2/grid interval does not significantly improve the accuracy of the solution. Two-dimmsional calculations using the new method were carried out to simulate laboratory model displacements in which gravity caused overriding of solvent. Good agreement between observed and computed profiles and measured and computed concentrations of produced fluid was obtained for a viscosity ratio of 1.89; at higher viscosity ratios, fair agreement was obtained Computed results were found to be significantly affected by vertical dispersion, and negligibly affected by dispersion in the direction of flow, in agreement with conclusions based on experimental observations. INTRODUCTION Although miscible displacement processes are potentially of great economic significance, limited progress has been made in developing mathematical methods for predicting the outcome of a solvent flood. Because of the complexity of the partial differential equations which describe multidimensional miscible displacement, numerical methods are a natural approach to their solution. The task of finding suitable numerical approximations to one of the partial differential equations, which involves both dispersion and convective transport, has been particularly difficult. Dispersion in the absence of transport is described by the heat flow equation, a second-order equation of parabolic type. This equation has been very successfully treated by numerical methods. Transport in the absence of dispersion is described by a first-order equation of hyperbolic type. This equation has been treated numerically with some success in one dimension, both by Lagrangian and Eulerian techniques, 1.2 but extension to two or more dimensions has not been satisfactorily accomplished. Usually one of two things happens: either the numerical solution develops oscillations or it becomes smeared by artificial dispersion resulting from the numerical process. When transport and dispersion are considered simultaneously, this numerical dispersion may dominate the low physical dispersivicy that generally characterizes miscible displacement. Stone and Brian2 have developed a new difference equation for treating combined transport and dispersion in one dimension. By suitable choice of certain parameters, they succeeded in markedly reducing both oscillation and numerical dispersion. However, a satisfactory extension to higher dimensions has not yet been found. Peaceman and Rachford3 presented a centered-in-time and centered-in-distance difference equation combined with a 1,transfer of overshoot" procedure which was demonstrated to work well in one dimension. The technique was applied to the two-dimensional miscible displacement problem, but subsequent calculations with zero dispersivity showed little change in results compared with the calculations they presented. This indicates that their method involved a numerical dispersion of the same order as the physical dispersion. The present paper describes an alternate method for solving the combined transport-dispersion

Jan 1, 1965

By P. M. Kelly, E. P. Butler

Four Mn-CLL alloys, containing 60, 70, 80, and 90 pct Mn, respectively, have been examined in the quenched and the quenched and aged conditions using electron microscopy and electron, neutron, and X-ray diffraction. After certain heat treatments the alloys transform from fee to fct and in the tetraom1 condition show a domain structure parallel to {101} planes. Neutron diffraction indicates that the domains are antiferrornagnetically ordered. The domain boundary contrast has been examined using bright- and dark-field microscopy, and the contrast effects observed under favorable conditions have been used to deduce the c axis orientation in each domain. The domains are extremely mobile and can be nucleated at precipitate particles and screw dislocations. The domain mobility is responsible for the high damping capacity. In the aged material a Mn precipitates in the Kurdjumov-Sachs orientation and results of both electron microscopy and neutron diffraction indicate that the matrix separates into two components—one rich in manganese and the other rich in copper. ALLOYS of manganese and copper have the unusual combination of a high damping capacity and good mechanical properties and have been the subject of a number of investigations as part of a general interest in high damping capacity alloys for engineering purposes.&apos;,&apos; SO far, however, there has been no reported electron metallographic study of these alloys. The Mn-Cu system has an extensive range of solid solubility at high temperatures, and the equilibrium phases are expected to be y (fee) and a Mn. The high damping capacity is associated with a metastable tetragonal structure of variable c/a ratio, which forms from the high-temperature y phase. This latter phase becomes more difficult to retain as the manganese content increases, and alloys containing more than 82 wt pct Mn undergo a reversible martensitic fcc — fct transformation on quenching. The X-ray work of Basinski and christian3 showed that the Ms temperature for the transformation was below room temperature for alloys in the range 70 to 82 pct Mn and increased linearly with manganese content. When quenched from the y region, alloys in the range 50 to 82 pct Mn are cubic at room temperature, but become tetragonal if aged at temperatures between 400" and 600°C. The martensite transformation occurs on cooling from the aging temperature. Tetragonal alloys have a banded microstructure and the bands analyze to be traces of (110) planes. Similar microstructures have been observed in In-Tl4 and in other manganese-base systems, such as Mn-Au5 and Mn-Ni.6 The mobility of the bands in Mn-Cu alloys can be demonstrated by optical examination of a polished specimen surface subjected to a cyclic stress.7 The bands appear and disappear as the stress is varied, and X-ray measurements of the (200,020) and (002) peak intensities confirm that a reversible reorientation of the tetragonal structure occurs. Meneghetti and sidhu8 investigated the magnetic structure of Mn-Cu alloys and found antiferromagnetic ordering in furnace-cooled alloys of composition >69 at. pct Mn. Magnetic super lattice reflections occurred at the (110) and (201) positions and the proposed structure was fct with the spins along the c axis. A more complete investigation by Bacon et al.9 confirmed this structure. The magnetic ordering temperature Tn was found to increase linearly with manganese content in the same way as the Ms temperature, and at any composition, Tn > Ms. This relationship suggested that the magnetic ordering was responsible for the cubic — tetragonal transformation in the manganese-rich alloys. The purpose of this investigation was to study the mechanism of high damping and the structural changes that occur on aging. The main technique used was transmission electron microscopy, but X-ray and neutron diffraction experiments were also carried out. EXPERIMENTAL Materials and Heat Treatment. The four alloys, provided by the Admiralty Materials Laboratory. were of nominai composition 60, 70, 80, and 90 Mn and all had low impurity levels, <0.05 pct C, <0.2 pct Fe. This material was cold-rolled to 200-µ strip with intermediate annealing and then given a final heat treatment of 24 hr in the range 800° to 900°C followed by water quenching. An identical heat treatment was given a length of 3/4-in.-diam bar of the 70/30 alloy from which the neutron diffraction specimens were machined. It was suspected that the tetragonal structures would be metastable at room temperature, and so the alloys were not aged until required for experiments. After aging in a salt bath the alloys were water-quenched. Thin Foil Preparation. Initial thinning to 50 to 75 µ was possible in a solution consisting of: 50 ml nitric acid 25 ml acetic acid 25 ml water The surface deposit and grain boundary etching was removed by a final electropolish at around 20 V in an electrolyte consisting of:

Jan 1, 1969

By Hallan N. Marsh, Bruce H. Robinson

It is generally believed that the flowing of wells through tubing instead of casing results in the conservation of gas. It is further believed that use of tubing prolongs the flowing life of a well and results in greater ultimate recovery, provided either that there are no adjacent wells, or that any adjacent wells are similarly operated. Recent experience in the flowing of Buckbee zone wells at Santa Fe Springs has not only substantiated both of these beliefs but has led to the further conclusion that the use of tubing results in a greater cumulative flowing production, &apos; even in a highly competitive field like Santa Fe Springs, where the wells concerned are closely offset by wells of both the same and other companies flowing through casing. Further, gas-oil ratio has been so reduced that greater ultimate recovery can be expected. In the belief that such would be the case, the majority of the Buckbee zone wells of one company were brought in through tubing, but enough wells were flowed through casing to form the basis for a comparison. For the purpose of this comparison, wells with flow strings 2½ or 3-in. dia. are designated as tubed wells, while those having flow strings larger than 3-in. dia. are designated as untubed wells. Casing used was mostly of 5 ¾-in. dia., the remainder being of 4¾-in. dia. There were 15 tubed wells and 8 untubed wells and they were scattered over the field in such a way that neither group appears to have any distinct advantage as regards location. Locations of all wells involved in the comparison are shown on Fig. 1. All the Buckbee sand wells of the company are included in the average production curves, with the exception of eight that were unsatisfactory for reasons other than the method of flowing. Findings 1. Buckbee sand wells flowing through casing larger than 3 in. had an average maximum production rate of 4670 bbl. per day, while wells flowed through straight tubing or 3-in. casing had an average maximum production of only 3300 bbl. per day. (See Fig. 2.)

Jan 1, 1932

By J. A. Jargon, H. K. van Poollen

Flow of slightly compressible fluids through porous media can be described by linear equations. Many mathematical solutions- are available for the boundary conditions of constant terminal pressures or constant flow rates, or a combination of both. Various techniques of formation evaluation use drastic rate changes, such as sudden shut-in. Other methods require that the well be produced at a constant rate. In practice, one is not always able m fulfill these rigid requtirements. This report shows a methor1 by which varying-rate data can be converted to a constant-rate pressure response, called the unit response function. After obtaining the unit response function, one may analyze it, using techniques described in the literature. The method uses tile principle of superposition. Necessary data is a time history of pressure and production. If pressure changes and/or rate changes are very drastic, the unit response function becomes erratic and oscillates The erratic and oscillating results are obvious, and under those circumstances, no answer can he obtained. It appears, however, that a response function without oscilla-tion will not contain any appreciable errors —- one gets either good results or no results. This report includes a mumber of examples of converting constant-rate data to constant terminal-pressure data and vice versa. In addition, a number of field-test applications are given. This method should be useful in converting mathematical solutions from one boundary condition to another. It already has proven useful in converting varying-rate data to constant-rate conditions. INTRODUCTION Pressure drawdown tests are performed on production wells to determine various reservoir characteristics, including permeability, distances to discontinuities, reservoir continuity and wellbore conditions. An ideal drawdown test is performed at a constant production rate with pressure observation during the drawdown period. A typical drawdown curve for a constant rate of production is shown in Fig. 1. In practice, a constant production rate cannot always be maintained. Fig. 2 shows a pressure drawdown curve for a varying rate. Usual methods of analysis are not applicable to tests such as this. It is, therefore, necessary to convert the varying-rate data somehow, before usual analytical techniques can be applied. This report describes a method of obtaining a response function. A response function can be defined as the relationship between pressure and time for a well producing at a constant unit rate. Such a response function can be analyzed by the usual analytical techniques. Hutchinson and Sikora&apos; first approximated a resistance function (response function), and by applying the superposition principle, pressures were calculated using the varying rates. If no match was obtained, adjustments were made to the response function and the closer approximation was used again in an attempt to match calculated and observed pressure behavior. If a good match was obtained: the response function was then used to extrapolate the future aquifer behavior.

Jan 1, 1966

By J. W. Lacey, F. H. Brinkman, J. E. Faris

This paper presents an analysis of the high-pressure, gas-driven LPG-slug process, based on fluid flow tests in areal models. Two types of tests were made. One series was made in low-pressure models which permitted observation of fluid movement. Three completely misci-ble analog fluids were used. A second series of tests was made in high-pressure models using methane, propane and a light refined oil saturated with methane at room temperature and 1,550 psig. Under the test conditions of room temperature and a pressure level of 1,550 psig, the phase diagram for the fluids used is similar to those for many of the field systems where the process is considered for use. A method for using these laboratory data to calculate field performance of the process is outlined. As a result of this work, it is concluded that small banks of LPG (5 per cent HV or less) are not effective in increasing oil recovery in horizontal reservoirs. Znstead, where small banks are used, the driving gas quickly penetrates the LPG bank because of fingering and channeling; and from this point on, the process behaves essentially as an immiscible gas-injection project. The validity of this conclusion was substantiated by: (1) laboratory studies of the effect of rate, model size and mobility ratio on miscible displacement in areal models; and (2) calculation of field recovery, which compared closely with actual field recovery. INTRODUCTION Field applications and pilot tests of the gas-driven, LPG-bank, oil-recovery process are on the increase. Most of these tests are employing small banks (2% to 5 per cent hydrocarbon volume) of LPG, which is miscible with both the driving gas and the oil in place, in an effort to attain an effective yet economical miscible displacement of oil by gas. The expectation of miscible displacement with small banks is based on the concepts that: (1) lengths of solvent-oil mixed zones, measured during miscible displacements in long slim cores, are representative of those that will occur in the field; and (2) areal sweep efficiencies5 measured in electrolytic model studies are applicable to miscible displacement in reservoirs. Our experimental evidence indicates that the mixed-zone lengths and sweep efficiencies mentioned are not applicable to miscible displacement in reservoirs. In this paper we present an evaluation of the gas-driven, LPG-bank oil-recovery process based on fluid flow experiments in areal models. These results are used to predict the performance of a field pilot test of this process, and the results are compared with the actual test results. THE EFFECTIVENESS OF LPG BANKS The effectiveness of LPG banks of various sizes in accomplishing miscible displacement of oil by gas was determined by displacement tests in a model representing one-quarter of a confined five-spot pattern. The model, 12 X 12 X 1/4 in. in size, was packed uniformly with glass beads. It was operated at a pressure of 1,550 psig and at room temperature; the fluids used were methane, propane and refined oil saturated with methane at 1,550 psig. The saturated oil had a viscosity of 1.2 cp at room temperature. The results of these tests are shown in Fig. 1, where recovery is plotted as a function of the volume of fluid injected for: (1) an immiscible-gas drive with an oil-to-gas viscosity ratio of 85; (2) three sizes of LPG banks; and (3) two completely miscible displacements with mobility ratios of 85:1 and 10:1. (The miscible displacement data plotted are the averages of several tests.) The results show that a 2½ per cent bank of LPG does not increase oil recovery over that obtained by immiscible-gas drive. The 7 and 17 per cent banks are, respectively, about 30 and 50 per cent effective (with reference to the M = 85 miscible-displacement curve) in increasing oil recovery at the point where 2½ hydrocarbon volumes (HV) of fluid have been injected. The percentage effectiveness of the banks at a given volume of fluid injected is defined as Recovery by Bank — Recovery by Gas Drive Recovery by Miscible Recovery by Flooding Gas Drive We conclude from these results that banks of LPG smaller than about 5 per cent HV in an individual stratum will cause from little to no increase in oil recovery. This finding was substantiated by work in low-pressure models, which permitted visual observation of fluid movements. In these tests, three completely miscible fluids having the same viscosity ratios as those used in

By M. C. Miller, M. R. Tek, D. L. Katz

Previous studies have shown the influence of geometric variations on the drawdown and buildup behavior of a well completed in a homogeneous, porous medium containing a single-phase fluid. Other papers have shown the influence of leakage across caprocks on drawdown tests on water wells and aquifers. This paper presents two additional cases: the influence of an adjacent, expansible source of fluid, and the effect of caprock leakage on the measured in situ permeability and compressibility. Methods are developed for evaluating the influence of these two deviations from a uniform aquifer upon the in situ permeability and compre.ssibility indicated by pump tests. INTRODUCTION In relatively uniform porous media, saturated with a single-phase fluid, the effective reservoir permeability and compressibility of the water porous bed system may be obtained from drawdown and build-up data on wells, such as the initial wells drilled in aquifer storage reservoirs (Homers and Katz et al.7). In considering the drawdown and build-up behavior of wells adjacent to storage reservoirs, or of wells in an aquifer adjacent to an unknown gas field, questions arise as to the quantitative effect of the presence of compressible fluid on the measured permeability and compressibility of the formation. The solution to this problem is presented, using a constant pressure line source at some distance from two wells, one of which is pumped and the other used as the pressure observation well. The solution is presented in terms of the geometry of the wells and their relationship to the constant pressure line. It is known that caprock leakage can interfere with the determination of an aquifer in situ permeability and compressibility (Mantush4, Hantush and Jacob3 and Witherspoon and Muellerll). This paper presents an added case of the effect of leakage through a caprock of known thickness and permeability on well tests starting with a reservoir of constant pressure above the caprock and contributing to the aquifer as a result of the pump test. Again, both a pumping well and an observation well are postulated. These two cases are presented together since both a compressible fluid nearby and. caprock leakage show similar deviations from expected in situ permeability and compressibility results, and the solutions are similar in form. EFFECT OF A NEIGHBORING CONSTANT PRESSURE SOURCE ON IN SITU MEASUREMENTS Bixel, Larkin and van Poollenl presented a paper showing the influence of a discontinuity of the properties of a fluid formation system on drawdown and build-up performance. Their case is related to the present study but may be distinguished from it in that their numerical work and resulting graphs relate only to the performance of the pumping well itself. Incorrect values for in situ reservoir properties may be obtained from pump test data if the skin effect of the well and after-flow are not considered. Analysis of this problem by the authors indicated that the more reliable method of evaluating the influence of an adjacent gas field or expansible source was to use one well for pumping and another well at some distance from it for observing the aquifer pressure performance. An expansible source of hydrocarbon near a pumping well may be approximated by a line of constant pressure for a pump test. Fig. 1 illustrates a pumping well and an observation well near a line of constant pressure. Pressure behavior of an observation well during a drawdown pump test near a line of constant pressure is given by the diffusivity equation:

Jan 1, 1967

By B. H. Caudle, L. G. Davies, I. H. Silberberg

This paper presents a method of predicting the recovery and performance of a five-spot steam injection project, in which a realistic approach to pattern sweepout efficiencies is made. Published methods for radial systems were modified for the five-spot pattern by approximating the stream lines with straight lines radiating from the injection well and then converging to the producing well. In each radial segment, the position of the steam front and the temperature profile ahead of the steam front were determined by heat balance equations, which included an estimation of heat losses to surrounding formations. The location of the saturations behind the cold water front was determined from a Buckley-Leverett solution to the material balance equation. Results from this program show steamflood recovery in a five-spot pattern to be considerably less than that predicted for true linear or radial flow systems. For a specific reservoir containing 900-cp oil, a steamflood in a purely radial flow system was predicted to recover more than 75 percent of the original oil in place when 2 PV of water had been injected as steam. A five-spot steamflood with otherwise identical properties was predicted to recover 10 percent of the original oil in place when 0.15 PV of water had been injected as steam and to recover almost no oil thereafter. A cold water five-spot flood in this system was predicted to recover approximately W percent of the oil in place with I PV of water injected. For a five-spot pattern in an example reservoir with 10-cp oil, steam injection similarly showed lower ultimate recovery than water injection but no improvement in recovery rule. Introduction The thermal recovery method considered in this study is steam injection in a five-spot pattern. Pattern steam injection has been given little attention in the past, possibly because of some rather obvious disadvantages. Unless steam temperature is maintained throughout the entire swept area, the process will revert to simple waterflood with all heat being lost prior to reaching the oil bank. Also, the oil viscosity reduction takes place near the steam front and not around the producing wellbore, so that low producing rates must still be endured. This is the reason for the success of the steam stimulation, or cyclic injection, in which the fluids are produced from the same well used for injection. On the other hand, steamflooding can offer some advantages. Oil displacement is by four methods: (1) mechanical displacement by the condensed water, (2) viscosity reduction of the crude oil, (3) swelling of the crude oil, and (4) distillation of the crude oil in the steam zone. Although dependent upon the crude, laboratory experiments have shown displacements up to 80 percent by steamflooding. In addition, steam is a good heat transport medium, since it is cheap and has a high heat content. Previous Investigations Previous publications have reported methods for predicting recovery in a steamflood for linear and radial systems. Since no pattern sweep efficiency is taken into consideration, the recovery even from a radial system must be greater than from more realistic geometries such as the very common five-spot patterns. Probably the broadest coverage is given by Willman who reported experimental results and offered a method of predicting recovery for a radial flow system. They concluded that both hot water and steam injection recover more oil than an ordinary waterflood, and that steam injection could yield recoveries "as much as 100 percent greater than by water flood." They also concluded that both the heat requirements for a reservoir and the residual oil remaining in the reservoir after steam injection were independent of the amount of oil originally in place, that short exploitation times were desirable, and that a high percentage of net sand in the reservoir with a high initial oil saturation was desirable. The method assumes that the flood occurs in three concentric cylindrical zones: (1) an inner steam zone, (2) a central hot water zone, and (3) an outer cold waterflood zone. Displacement in the steam zone is based on laboratory-determined residual oil saturations while the hot water and cold water zones use the conventional Buckley-Leverett equations. Although the results shown by Willman et al. are for a radial system flowing out from the well to an assumed external circular boundary, their equations did

Jan 1, 1969

By H. S. Choi, I. Iwasaki

The effect of temperature as a parameter in ore flotation has not been systematically studied, although for some ores it has been known for many years that selectivity and grade of concentrates can be improved by conditioning or flotation at moderately or substantially elevated temperatures. In 1934 Coghill and Clemmer&apos; stated that "elevated temperature seems to make hard water more tolerable" in soap flotation, and a cursory examination of the literature indicates that some earlier investigators were aware of beneficial results obtained by floating above room or mill-water temperatures. Tartaron,2 Mitchell et aL.,3 and particularly Hamilton et al.&apos; have shown that high pulp temperatures give high recovery and selectivity in soap flotation of fluorite from a variety of gangue minerals. As a result of the work of these and of other investigators, high-temperature flotation has been successfully applied to industrial flotation of fluorite. Falconer" stated: "The use of high temperature conditioning (above 35°C and preferably above 60°C) in connection with the soap flotation of nonsulphide ores, as covered in B. Kalinowski&apos;s French Patent No. 847,-215, Dec. 7, 1938, is claimed to provide more intense activation, better separation of values from gangue, and reduction in quantity of reagents." The various investigations quoted above clearly demonstrate the improvements to be realized by increasing the temperature at which fluorite is floated, and it is surprising that little or no information has been published on systematic investigation of the same method as applied to other ores. The present article describes comparative results obtained at room temperature and at elevated temperatures by otherwise conventional flotation of iron ores, by single-mineral flotation in the Hallimond tube, and by contact-angle measurements. It is not the purpose of this article to evaluate the commercial feasibility of high-temperature flotation of iron ores, although preliminary calculations show that the cost should not be excessive and that the gains to be realized may well outweigh the extra cost of heating the pulp. LABORATORY FLOTATION TESTS Experimental: All flotation tests reported in this article that use a laboratory Fagergren cell were made on ore A (either containing the primary slimes or deslimed at 20µ as specified) following the preparatory procedures described elsewhere- or this particular ore. Ore A contained hematite, goethite (limonite), quartz, chert, and minor quantities of magnetite. Confirmatory tests made on other ores show that the same general principles apply to ores of similar mineralogy and structure. Conditioning was performed by adding the collector, as a soap, to the vigorously stirred and heated pulp. Conditioning time was 5 min, the pulp contained 60 pct solids, and the equivalent of 0.5 Ib of fatty acid was added per ton of original (unde-slimed) ore. The pH of the pulps ranged from 6.8 to 7.1 (25°C measurement) during conditioning. The pH was adjusted in the flotation cell by addition of either NaOH or H2SO4, the values reported being those of the pulp cooled to 25°C. During conditioning and flotation the pulp temperatures were controlled within l° to 2° by immersion of Variac-controlled Calrod elements in the conditioning beaker and in the cell, and by the use of water, heated to the appropriate temperature, for transferring pulp, adjusting pulp volume, and washing. Selectivity indexes have been calculated on the same basis as those reported in the article by Cooke, Iwasaki, and Choi." Results: Table I gives the results obtained by floating deslimed ore A with pure oleic acid at 25" and 50°C, and Fig. 1 shows the selectivity indexes plotted against pH of flotation. Inspection of Table I

Jan 1, 1961

By M. M. Leighton

INASMUCH as the arrangements for the preparation of the review of progress and new developments in the field of industrial minerals (non-metallics) were not made until early December, the writing of this review could not be completed in time to appear in this issue and will, therefore, appear in the February issue. However, we desire to call attention to the steadily increasing importance of this group of mineral substances. The recent book, "Industrial Minerals and Rocks," published by the Institute, lists 47 principal varieties of nonmetallic minerals to which may be added several more of lesser importance. Because of the wide variety of uses to which many of these industrial minerals are put, it is difficult to classify them into categories, but to mention a few examples which indicate the widespread industrial employment of these minerals and their products, one may cite: the use of limestone, gravel, sand, clay products, lime, cement, and gypsum in the construction industry; fluorspar, lime, salt, borax, and sulphur in the chemical industry; diamond, corundum, emery, garnet, flint, quartz sand, tripoli. and diatomite in the abrasive industry; fluorspar, limestone, and magnesite in the metallurgical industry; clay, feldspar, fluorspar, flint, chalk, and limestone in the ceramic industry; and asbestos, gypsum, mica, vermiculite, magnesia, diatomite, and rock wool in the heat, sound and elec-

Jan 1, 1940

By S. Vela, R. M. McKinley, L. A. Carlton

Johnson et al. have described a new well-testing technique that measures formation flow properties between wells.&apos; The technique, called pulse-testing, requires a sequence of rate changes in the flow at one well and measzcrement of the re.rulting pressure changes at an adjacent well with a very sensitive differential pressure gauge. This paper describes an extensive application of the technique in a producing oil field. Pulse-tests on 28 of 45 possible well pairs in the field provided a picture of the areal distribution of reservoir hydraulic diffusivity, trans-missibility and storage. The primary objective in presenting these data is to demonstrate the potential of the methcid for reservoir description. A second objective is to show in three ways the qualitative and quantitative accuracy of reservoir parameters determined from pulse-tests: (I) pulse-test data show a nonuniformity in the field, closely correlating with the oil-water distribution as given by production data: (2) pulse-test values for permeability are comparable with core va1ue.s; and (3) perhaps most important, the field responds to a conventional interference test in the manner in which pulse-test data predict it should. The pulse-testing technique by Johnson et al.&apos; is an ideal source of data for purposes of reservoir description, for it provides a measurement of formation storage S = +ch, hydraulic diffusivity 91 = k/+cp and transmissibility T — This paper describes an application of this method in a producing oil field. Results were analyzed to give numerical values for the parameters 7, T and S. These values were compared with oil-water production data (for the effect of fluid saturation), with core data and with data from an interference test. The reservoir in which the pulse-test survey was run is the result of a structural trap formed by a fault along the east side of a north-south trending anticline. A down-structure aquifer providcs a natural flank water drive for the pool. The producing formation is a dolomitic lime- stone having mainly vugular permeability; the formation oil has a gravity of 29" API with negligible dissolved gas. The field contains 19 wells, all on pump, arranged on 40-acre spacing along the top of the anticline. Fig. 1 shows the location of all these wells except two at the south end of the field. The dashed line on the right-hand side of the figure represents the approximate location of the fault with respect to well positions. Pulse-Test Survey and Analysis of Data A pulse-test requires a pulsing well and a responding well. In the field, changes were made in the rate of flow at the pulsing well by stopping and starting the pump periodically and measuring the corresponding pressure

Jan 1, 1969

By H. H. Rachford

Numerical solutions of immiscible flow problems in which dispersive effects of capillarity are dominated by convection require excessively fine grid spacing with attendant high computing costs. The use of coarser spacing reduces cost but often produces oscillation or undue dispersion associated with displacement fronts, A numerical formulation is proposed here which should be applicable to two-dimensional flow problems. it is in part analogous to an approach previously tested for miscible systems. The convective transport is approximated using a change of variables to yield a coordinate system moving approximately with the local characteristic velocity. The capillarity-induced dispersive terms in the differential system describing the process are approximated with respect to a fixed coordinate system by the usual implicit formulation. One-dimensional tests of the procedure yielded results in which the saturation profiles tended smoothly to the zero-capillary pressure solution as the ratio of viscous to capillary forces was successively increased in a sequence of calculations. This contrasted favorably with solutions by other numerical procedures which would require attendant grid refinements to approach the zero capillary pressure results. INTRODUCTION Numerical solution of displacement problems has until recently relied on applying methods developed primarily for transient heat-flow problems. Such problems are classified as parabolic in type, and where the heat transport is purely by diffusion their solutions are characterized by a high degree of smoothness. It is not surprising, therefore, that for approximating these solutions available finite difference methods are quite adequate. In flow problems the transport is partly by diffusion, partly by convection or flow. Although the problem remains of parabolic type because the dispersive effects of capillary forces or diffusion play some role in every displacement, at high flow rates the problem is dominated by convection, and solutions tend toward those of equations of the hyperbolic type. Solutions of hyperbolic problems are characterized by the translation of fronts, or discontinuities, that may progressively increase in sharpness. Numerical methods for treating parabolic problems become less and less satisfactory as displacement rates increase and the role of dispersion due to concentration or capillary pressure gradients becomes small relative to transport due to flow. In computation the difficulty manifests itself as an error associated with the grid size chosen. 1-6 In summary, if the heat-flow type approximations are to include the terms arising due to convection, one of several choices may be made: (1) an upstream (to the direction of flow) approximation for the convection terms may be used; (2) a centered-in-distance (CID) approximation may be used; or (3) a recently developed approximation based on the theory of oscillation matrices may be chosen.6 The last appears to have significant promise for one-dimensional flow problems; its extendibility to two or three dimensions is an open question. In either of the first two approaches, a suitably small ratio of v&/D must be maintained, where v is the velocity, & is the grid spacing and D the effective dispersivity in the direction of flow. In the first choice, the approximation of the convective part is only first-order correct and errors introduced appear as a numerically induced dispersivity of magnitude proportional to v?x. In the CID choice, the approximation can be second-order correct, but the difference formulation fails to satisfy the maximum principle unless a condition on v?x/D is met. Practically, this means that for high flow rates oscillatory solutions may result in the neighborhood of a front unless exceedingly small grid intervals are taken. While the procedure proposed by Stone and Brian4 permits a less severe limitation to be placed on this ratio, ultimately the flow rates increase relative to the dispersivity the oscillation obtains. Further, extensions of their approach to higher dimensional systems may be attended by considerable

Jan 1, 1967

By M. C. Leverett, M. E. True, W. B. Lewis

This paper states the theory underlying the design of two kinds of dimensionally scaled models of parts of idealized oil fields. One of these simulates an oil well and its surrounding sand for a distance of 16 ft. radially from the well. The other model simulates linear flow through layered sands. Construction and operation of the models are described and typical data are given. The unique features in the design of the models are: (I) the treatment of the permeability-viscosity quotient as a single variable and (2) the use of previously reported experimentally developed relations between relative permeability and saturation and capillary pressure, saturation, porosity, permeability and interfacial tension. The models at present simulate flow of oil and water only, through unconsolidated sands. They are superior to unscaled models, which may give rise to erroneous conclusions. The models are designed to study the desirability of various methods of well completion and the effects of various factors on recovery of oil from layered sands. Introduction Recent work on the fundamental behavior of flowing mixtures of fluids in sands has resulted in the development of some new theory in this field, much of which has been presented in previous papers.l-4 However, the application of this theory to the behavior of oil wells or oil fields has proved too complicated for ordinary mathematical techniques, except in very highly simplified cases. A practical solution to this problem appears therefore, to lie in the use of dimensionally scaled models of elements of oil fields. The object of this paper is, first, to present the theoretical and experimental basis of the design of such models, and, second, to describe their construction and operation. Experiments now under way on the models already built will yield material for other reports, which will be devoted to interpretation of the results in terms of oil-field behavior. So far, simple dimensional models of two kinds have been built and are being operated. These models represent different parts of an idealized oil field but obey the same underlying theory. The only fluids represented are oil and water, since certain questionable approximations are necessary for gas-liquid systems. General Theory Dimensional models have been used in other fields for a long time, and their theory is adequately given in the literature. 5 Here, it suffices to state that each physical element entering into a dynamic relation may be given a definite description in terms of three fundamental, but arbitrarily chosen, dimensions. These usually are mass, length, and time, symbolized here by the small letters m, I, and t. Two systems are said to be dimensionally similar or dimensionally scaled if for each element in one system there is a corresponding element in the second system and the ratios of the numerical magnitudes of corresponding elements are constant for all elements of the same dimensional type.

Jan 1, 1942

By W. B. Lewis, M. E. True, M. C. Leverett

This paper states the theory underlying the design of two kinds of dimensionally scaled models of parts of idealized oil fields. One of these simulates an oil well and its surrounding sand for a distance of 16 ft. radially from the well. The other model simulates linear flow through layered sands. Construction and operation of the models are described and typical data are given. The unique features in the design of the models are: (I) the treatment of the permeability-viscosity quotient as a single variable and (2) the use of previously reported experimentally developed relations between relative permeability and saturation and capillary pressure, saturation, porosity, permeability and interfacial tension. The models at present simulate flow of oil and water only, through unconsolidated sands. They are superior to unscaled models, which may give rise to erroneous conclusions. The models are designed to study the desirability of various methods of well completion and the effects of various factors on recovery of oil from layered sands. Introduction Recent work on the fundamental behavior of flowing mixtures of fluids in sands has resulted in the development of some new theory in this field, much of which has been presented in previous papers.l-4 However, the application of this theory to the behavior of oil wells or oil fields has proved too complicated for ordinary mathematical techniques, except in very highly simplified cases. A practical solution to this problem appears therefore, to lie in the use of dimensionally scaled models of elements of oil fields. The object of this paper is, first, to present the theoretical and experimental basis of the design of such models, and, second, to describe their construction and operation. Experiments now under way on the models already built will yield material for other reports, which will be devoted to interpretation of the results in terms of oil-field behavior. So far, simple dimensional models of two kinds have been built and are being operated. These models represent different parts of an idealized oil field but obey the same underlying theory. The only fluids represented are oil and water, since certain questionable approximations are necessary for gas-liquid systems. General Theory Dimensional models have been used in other fields for a long time, and their theory is adequately given in the literature. 5 Here, it suffices to state that each physical element entering into a dynamic relation may be given a definite description in terms of three fundamental, but arbitrarily chosen, dimensions. These usually are mass, length, and time, symbolized here by the small letters m, I, and t. Two systems are said to be dimensionally similar or dimensionally scaled if for each element in one system there is a corresponding element in the second system and the ratios of the numerical magnitudes of corresponding elements are constant for all elements of the same dimensional type.

Jan 1, 1942

By G. T. Davis, C. C. Mattax, M. O. Denekas

The effects of crude oil cornponents on the wellabil-ities of sandstone and limestone were investigated. Fractions containing cornponents differing in molecular weight and molecular structure were obtained from crude oils by distillation, extration and chromatography. Individual fractions were then tested for their effects on rock wettability. Tests indicate that sundstone wetta-bility may he changed by a complex variety of surfactants varying both in molecular structure and molecular weight. Limestone appears to be particularly sensitive to basic, nitrogenous surfactants. INTRODUCTION Investigations in recent years have shown that petroleum reservoir rock wettability can exert a significant influence on the efficiency with which oil can be produced by water flooding. While most reservoirs are presumably water-wet, they niay range in their degree of water-wettability from near-neutral to strongly water-wet.&apos;" Reservoir wettabilities other than strongly water-wet are likely to be induced by adsorption of surface-active components froni the crude oil on the pore walls of reservoir rock.:&apos; Little is known, however, about the nature of the surface-active materials which are likely to be adsorbed by the reservoir rock. Due to the complexity of crude oils. attempts made in the past90 isolate these surface-active components have met with only limited success. It is probable that many different types of surface-active materials arc indigenous to crude oils and that many of these may be adsorbed to varying degrees by reservoir rock. This was cxolored in the studies discussed in this paper. The over-all objective in these studies is to ascertain whether the wettability of a given reservoir can be determined by examining the surfactant content of the reservoir crude. To this end, crude oils were examined to determine the variability of indigeneous surfactants with regard to chemical type and molecular weight. Crude oils were separated by distillation into fractions differing principally in molecular weight, by chroma-tography into fractions containing compounds differing in polarity, and by solvent extraction into nitrogenous and non-nitrogenous fractions. Individual fractions were then tested for their effects on the wettabilities of sandstone or limestone rock samples. EXPERIMENTAL PROCEDURES Fractionation of the Crude Oils Samples of Miocene, Eocene and Jurassic crudes were distilled at temperatures not exceeding 200°C. The final stages of distillation were completed in a molecular still at pressures down to three microns of mercury. Fifteen to 30 fractions were obtained from each crude oil. These cuts were sufficiently broad that separation can be considered to have been effected principally on the basis of the molecular weights of the constituents of the crude oil. A considerable portion (20 to 40 per cent) of the crudes would not distill under these conditions. The residues were recovered and tested with the other fractions. Fractions differing in polarity were separated from a crude of Pennsylvanian age and an extracted sample of Miocene oil by chromatography, using a solid adsorbent. Since surfactants are, for the most part, polar compounds, chromatography should separate many of the surfactants from the crude oil. Such a separation should provide fractions containing compounds differing in molecular structure. Nitrogeneous compounds were extracted from Miocene crude oil with a solution of sulfuric acid in meth-anol. The residual oil was further processed by chonia-tography. Each of the fractions obtained by thesc procedures was dissolved in a non-polar solvent (xylene) and diluted to its original concentration in the crude oil. No attempt was made to maintain an anaerobic atmosphere above the samples while they were being dissolved. These solutions of the fractions were then tested for their effects on the wettability of sandstone and limcstone as discussed in the next section. Measurement of the Effects of Crude Oil Fractions on Rock Wettability No entirely satisfactory method for measuring rock wettability has yet been developed. All methods used are empirical. The imbibition test was used in these studies. This test is based on the tendency of a rock to imbibe the wetting phase spontaneously. For example, if a strongly water-wet rock is first saturated with oil and then placed in water, the water will quickly invade the rock by capillarity and much of the oil will be displaced. If the rock is slightly water-wet, water irnbibition will proceed more slowly and, in many instances, considerably less oil will be displaced. A water-saturated, oil-wet rock will imbibe oil. The initial rate with which water (or oil) imbibition takes place indicates, qualitatively, the degree of water (or oil) wettability of the rock.

By A. G. Weber, H. J. Welge

A published calculation method for predicting incompressible, multidimensional fluid displacement has been adapted to the problems of water and gas coning in oil wells. Since depth and radial distance from the wellbore are the two key dimensions affecting the shape of a gas or water cone, coning calculations are well suited to the use of two-dimensional methods. The alternating direction implicit procedure (ADIP) was used for relaxation calculations of two-phase potentials in a two-dimensional grid. From the potentials and the capillary pressure relationship, saturation and pressure distributions were calculated which trace cone growth with time. Predictions have been made for well producing histories both before and after core breakthrough. To check validity of the method, two-dimensional calculations have matched the coning behavior and produced water-oil ratio history of a laboratory sand-packed model. They have also matched the coning behavior of several producing wells, for which the calculations were compared with produced water or gas cuts and logs showing water or gas cone movements. INTRODUCTION The application of two-phase, two-dimensional calculations using ADIP to various reservoir flow problems has been described in the literature.1-3 When adapted for computer solution, this method has proved to be a powerful tool for simulating well and reservoir behavior. This paper discusses the method as applied to well coning calculations. Single-well and coning calculations comprise an especially difficult class of two-dimensional problems which require special techniques for computer calculation and determination of reservoir characteristics. Refs. 4 through 8 describe previous approaches to the coning problem. Several examples of water and gas coning calculations, including studies on both laboratory models and producing wells, are presented here. The two-dimensional method accounts realistically for the most critical parameters affecting coning behavior, including production rate, formation stratification, horizontal and vertical permeabilities, depth of well penetration, gravity and capillary forces. The method considers the different densities and viscosities of the two phases and the relative permeability and capillary pressure characteristics of the rock and fluids. In addition to tracing cone growth in the vicinity of the wellbore, the method calculates the overall movement of the fluid interface throughout the well&apos;s drainage volume. Incompressible fluid flow is assumed to occur between the producing interval and the well&apos;s limit of drainage. Calculations can be made for the producing history both before and after cone breakthrough. A typical two-dimensional grid or array of blocks used to solve a coning problem contains about 400 blocks. The well&apos;s cylindrical drainage volume can be represented by about 20 radial subdivisions and the formation thickness by 20 vertical subdivisions. The grid spacing is normally smaller near the withdrawal interval to define the cone shape accurately. For this work we used an IBM 7074 digital computer having a core memory of 10,000 ten-digit words. A typical study, covering 5 to 10 years of well producing history, required from three to six hours of computing time. MATHEMATICAL SIMULATION OF CONING BEHAVIOR BASIC METHOD In coning calculations, the reservoir volume drained by the producing well is represented by a two-dimensional system of blocks as shown in Fig. 1 for water coning studies. The horizontal dimensions of the blocks increase with radial distance from the well axis in geometric progression, i.e., the block size is small near the wellbore and large near the well&apos;s drainage radius (re). Vertically, the blocks are bounded by horizontal planes located at different depths through the

Jan 1, 1965

By G. Thodos, E. M. Phillips

A reduced density correlation for the gaseous and liquid regions of ethane has been developed from all the experimental PVT data available in the literature for this substance. Saturated vapor and liquid densities reported for methane, propane and n-butane were utilized to establish the rectilinear-diameter line for ethane. This line was then used with the saturated-vapor data for ethane to produce the saturated envelope for this substance. Most of the saturated liquid data reported for ethane were found to be inconsistent with the saturated-liquid curve resulting from this study. The correlation covers the regions 0.65 < TR <6.0 and 0 < PR < 15. For regions for which no experimental data have been reported, the isobars of the correlation were extended by the use of the theorem of corresponding states. This correlation is presented both on rectilinear and log-log coordinates. INTRODUCTION At the present time, there is considerable interest in the exact PVT behavior of pure hydrocarbons. Matschke and Thodos12 recently have developed a comprehensive compilation of experimental vapor and liquid density data for methane. Similar studies have been conducted for other pure substances.4, 7 In the present study the density data available in the literature for gaseous and liquid ethane have been critically reviewed and utilized to develop a reduced density correlation for this substance. SATURATED LIQUID AND VAPOR DENSITIES The rectilinear-diameter rule proposed by Cailletet and Mathias5 states that the sum of the saturated liquid and vapor densities of a pure substance is a linear function of temperature which passes through the critical point. This law, although empirical, has been well established by continued verification since its conception in 1886. This rule has been applied to the saturated density data of methane,6 propane 17 and n-butane8 to produce the straight lines presented in Fig. 1 which pass through the critical point TR = 1.00, Pr = 2.00. The rectilinear-diameter relationship for ethane was established from the lines for the other substances in Fig. 1 by plotting the quantity p~, + PR against zc for different reduced temperatures. A critical analysis of the saturated vapor and liquid densities reported for ethane by Kuenen,10 Maass and McIntosh,11 and Sage, Webster and Lacey18 revealed that the values of PR1 + pr resulting from these studies were inconsistent with the rectilinear-diameter line obtained from the reliable density data of the other substances, as shown in Fig. 1. In the analysis of these data, reduced quantities were calculated using the critical con-

By A. L. Barnes, A. M. Rowe

A heat transfer study was made of hot gas injection into oil shale through wells interconnected by vertical fractures. This analysis involved the simultaneous numerical solution of a nonlinear, second-order partial differential equation that describes two-dimensional conduction heat transfer in oil shale and a nonlinear first-order partial differential equation that describes convection heat transfer in the fractures. Three nonlinear, temperature-dependent coefficients were used in this work; they are thermal conductivity, thermal capacity and retorting endothermic heat losses of oil shale. Vertical fractures were considered to be of finite height. Although vertical conduction heat transfer was not considered, an estimate of the error resulting from this limitation was made. The effects of injected gas temperature, injection rate, system geometry, cyclic injection and time upon retorting efficiency were investigated. Results from this study show that the rate of retorting oil shale is a direct function of both injection temperature and rate, and the theoretical producing air-oil ratio:(AOR) is an inverse function of temperature. Retorting rates are constant until "breakthrough" of the 700 F isotherm at the producing well, assuming constant injection parameters. Retorting rates for bounded systems are higher than the analogous unbounded systems and likewise AOR&apos;s are less. The use of an alternating injection-soak routine with high injection rates is less efficient than continuous injection at lower rates. These results indicate that injection temperatures on the order of 2000F or greater may give theoretical AOR&apos;s in the economic range. INTRODUCTION Over half of the known oil shale reserves are located in the U.S., and most of them lie in the Piceance Creek basin of Western Colorado. The Colorado oil shale outcrops on the edges of the Piceance Creek Basin. At the outcrops the shale beds are relatively thin, from 25 to 50 ft thick. In the center of the basin the oil shale is as great as 2,000 ft thick and is covered with 1,000 ft of overburden. It has been estimated that there are over 1,000 billion bbl of oil in shales having an oil content over 15 gal/ton in this basin. Oil shale does not contain free oil but an organic matter called kerogen. Kerogen yields petroleum hydrocarbons by destructive distillation. It must be heated to approximately 700F, at which temperature it decomposes into shale oil, gases and coke. The U.S. Bureau of Mines and, more recently, oil companies have conducted considerable research on surface retorting methods to economically recover oil from this shale. Another approach to exploit the oil shale deposits, in particular that portion having 1,000 ft of overburden, is to retort the oil shale in place and produce the liquid and gaseous hydrocarbons through wells drilled into the shale. Some research has been done on this approach.l,2 There are several variations to the in situ retorting approach. These variations fall into one of two groups, depending upon the geometry of the system: (1) retorting in a highly fractured or broken up matrix; (2) retorting from single fractures between production and injection wells. The latter is the group studied. Several investigators,3-6 using various assumptions, have studied flow of heat through horizontal systems. The objective of this work was to make a heat transfer study of in situ retorting oil shale by hot gas injection through wells interconnected by single vertical fractures of finite height. The oil shale thermal conductivity, thermal capacity and retorting endothermic heat losses were considered to be functions of temperature. A knowledge of the

Jan 1, 1969

By C. H. Hewitt, J. T. Morgan

The Fry cocurrent in situ combustion project was carried out in a 3.3-acre portion of a lenticular body of Robinson sandstone of Lower Pennsylvanian age. This particular sand body is about 12,000 ft long and 3,500 ft wide; it varies in thickness from 0 to 55 ft, trends northeast-southwest, and occurs at depths between 880 and 936 ft. The reservoir is made lip of three distinct types of sandstone, each having characteristic reservoir properties. (See Table I.) Textural gradients, sedimentary structures, erosional basal contact, absence of marine fossils, and geometry of the sand body all indicate that the sandstone is of fluvial origin and part of an extensive complex of river-deposited sedirnents. Geographically oriented cores reveal that the direction of depositing currents was to the southwest, parallel with the sand-body trend. Directions of maximum pernleability also parallel the northeast-southwest trend. The layered nature of the sandstone reservoir and its directional properties have controlled the areal distribution of produced gas, the ignition behavior, and the vertical profile and horizontal extent of the conbustion zone. INTRODUCTION This paper is the first of a series of three papers that describe Marathon Oil Co.&apos;s Fry in situ combustion test. This first paper contains the results of a detailed study of the geology and reservoir characteristics of the Robinson sandstone reservoir in which the Fry test was conducted. The second and third parts of this series report on the field operations&apos; and performance. The geologic work reiated to cores cut through the combustion zone, and to the effect of reservoir properties on the combustion process is included in the third paper.&apos; GEOLOGIC STUDY OF THE FRY RESERVOIR The close spacing of continuous cores in the Fry combustion site provided an unusual opportunity to study the details of distribution of lithology and reservoir properties within a petroleum reservoir. The objectives of the study were: 1. To determine the distribution of rock types within the Robinson sandstone in the Fry area; 2. To determine the relationship of porosity and permeability to rock properties and establish the distribution and homogeneity of reservoir properties; 3. To determine the origin of the Robinson reservoirs so that attempts could be made to predict the size, shape, distribution, extent and continuity of Robinson reservoirs; and 4. To determine what effects, if any, the reservoir rocks might have on the combustion process, so that the process might be better evaluated. AVAILABLE MATERIALS Continuous cores were cut from 14 wells in the vicinity of the Fry site. Ten of the cores are from within the 3.3-acre pattern; six of the 10 were cut prior to combustion, and four were cut through the combustion zone. Cores from the Emma Fry No. 15, Wampler 0-2 and Fry B wells (Figs. 1, 2 and 9) were geographically oriented by the Eastman Oil Well Survey Co. Maps, electric

Jan 1, 1966

By Anthony Tuke

Members of the Society of Mining Engineers may well regard it as rather unusual that a paper on this subject is being presented by someone whose first taste of mining came at the age of 60 or so - someone who last heard of cathodes and anodes in 1938. On the other hand, the title does refer to the financing of a mine and at least I can claim to have spent all my business life since the war until 1981 in the world of banking, though this inevitably means that I have been used to looking at these and other problems through what you might regard as the wrong end of the telescope. The lending of money, and more particularly the provision of finance for commerce and industry, is the central job of a banker and I have been involved in this in various ways over many years, but regrettably only very marginally in the world of mining. As you will see from what follows, the rather specialised form of finance which RTZ required was, to my regret, not provided by the British banking community since the great majority of the finance came from American banks and, to a lesser extent, from German banks. I am most indebted to Mr. Roy Wright for a great deal of the nuts and bolts in this paper. He was one of the three central figures in the growth and expansion of RTZ during the 1950&apos;s and 1960&apos;s and was right at the centre of the negotiations with bankers, with governments and with many others. The going, as you will see, was far from easy. The essential basis for the financing of each of the RTZ group&apos;s mining projects was a firm long-term sales contract for sufficient of the output of the particular mine to produce the cash flow necessary to service the loans. Wherever possible, loans were raised in the same currency as the sales contracts were made. Each sales contract was designed to give the customer the product he wanted with a long-term assurance of supply and at the same time to give the bankers the protection they required. Thus the marketing concept and the financing concept for a particular mine formed one overall plan, and talks with the customers and the bankers were conducted in parallel until a satisfactory marketing/financial package was agreed in principle. Preliminary talks were begun soon after the discovery of a potentially viable orebody. As confidence about a discovery increased, customers were persuaded to enter into contingent sales contracts before the very detailed and costly business of the economic and technical feasibility study of the mine was launched; such a study might cost 10% or more of the estimated total capital cost. At the same time provisional understandings were reached with the bankers. The contingent sales contracts usually gave a period of grace of eighteen months to two years, during which time the decision whether or not to continue with the mine had to be made. This decision rested mainly on the result of the feasibility study and also on coming to a firm agreement with the bankers. If all went well and the mine went ahead, then the contingent sales contracts became firm, but they fell away if the decision was negative. The Company was fortunate that during the whole period when its major mines were being developed, world trade was increasing rapidly and Japan was becoming a dominant industrial power. The Japanese supported many of the mines, including Hamersley Iron Ore, Lornex Copper, Bougainville Copper to name a few, with the basic long-term sales contracts that enabled their development. The Germans supported Palabora and to a lesser extent Bougainville. The mines were financed as individual projects generally with a loan/equity ratio of about 65/35, without legal recourse to RTZ for the loans. RTZ was, however, responsible for providing any capital overruns required to bring the mines into commercial operations. Nevertheless, the RTZ management regarded itself as morally responsible to the lenders because, Palabora aside, the sales contracts had either a fixed selling price (like Hamersley), an indexed price (like the Elliot Lake Uranium Mines and Mary Kathleen), or a floor price (as in Lornex, Bougainville and Rossing). Thus the Company believed that any financial failure would have been due to poor management or technical

Jan 1, 1985